As of May 1976, some 38 Flue Gas Desulfurization (FGD) processes were being promoted by more than 100 sponsoring organizations and supported by more than 90 equipment manufacturers.
Those FGD processes which produce calcium sulfite/sulfate sludges containing ash as the end product have an estimated overall annualized cost in excess of $0.50 per million Btus fired and an estimated initial capital investment in excess of $100.00 per kilowatt of installed capacity. These costs do not include the values for site acquisition, site preparation and site rehabilitation for disposal or the operating or capital costs for pumping the sludges to the disposal site.
Those FGD processes which produce saleable products, such as anhydrous sulfur dioxide, sulfuric acid or elemental sulfur, have an estimated annualized cost of $0.35 per million Btus fired, with full market price credit of the by-products. The estimated initial capital investment cost in excess of $150 per kilowatt of installed capacity.
The consumption of coal combusted as fuel in the United States in 1976 has been estimated at 645 million tons. The average sulfur content of the coal is placed at 2.4 percent. To remove some 27 million tons per year of SO.sub.2 from the atmospheric discharges by any combination of presently promoted FGD processes, the out of pocket cost to the consumers in the United States would be between 4 and 8 billion dollars in 1976.
The numerous wet scrubbing FGD processes, producing calcium sulfite/sulfate sludges containing ash, cause the combustion flue gasses to pass through alkaline solutions, such as sodium hydroxide, sodium carbonate, calcium hydroxide, calcium carbonate or magnesium hydroxide. These solutions absorb 60 to 90 percent of the SO.sub.2 in the entering flue gas stream, forming sulfite/sulfate salts. Secondary process loops react these scrubber solutions to form precipitates. The precipitates are then concentrated to a sludge which is transported to a prepared, impermeable, permanent disposal site which must be rehabilitated for recreational, agricultural, industrail or residential uses.
The major disadvantages of the wet scrubbing FGD processes are:
1. The very large volumes, 60 gpm per MWe of scrubbing solution are required for recirculation throughout the primary scrubbing loop, continuously.
2. The volume of makeup water required is substantial, ranging from 1 to 5 gpm per megawatt.
3. The chemistry of the several loops is complex and results in impervious-to-water scale formation if precise chemical equilibriums are not constantly maintained.
4. Large quantities of flue gas heat must be dissipated in water slurries to effect SO.sub.2 removal by absorption and then the cooled flue gases must be reheated in order to effect atmospheric discharge up the stack.
5. The large volume of sludge generated, one to two cubic feet per megawatt-hour, have no major continuing market potential.
6. The large quantities of caustic, soda ash, lime, limestone or dolomite required to produce the chemical sludges are rarely within economical shipping distance of the use site.
7. The extensive land acreage required for the disposal of the chemical sludges are rarely adjacent to the existing power generating plant site, and are socio-economically and environmentally unacceptable for this purpose.
The primary process loops of the several dry FGD processes which produce marketable end products, such as anhydrous sulfur dioxide, sulfuric acid and elemental sulfur, cause the SO.sub.2 containing flue gasses to pass through sulfur dioxide absorbants, such as molten sodium carbonate, sodium aluminate or activated carbon and/or react with oxidizing catalysts, such as magnesium oxide, copper oxide and vanadium pentoxide. Secondary process loops regenerate the absorbants or catalyts, releasing the SO.sub.2 in a reasonably pure form, which, in turn, is further reacted to form the marketable product.
The major disadvantages of the dry FGD processes are:
1. The unfavorable chemical equilibrium reaction rates.
2. The high temperature and high BTU requirements of the primary reaction loops.
3. The high temperature, high BTU and high pressure requirements of some secondary regeneration loops.
4. The higher overall efficiency decrease in the net station output.
5. The replacement costs of the absorbant or catalyst.
6. Impure and/or dilute end products.
7. The limited geographical areas of profitable marketibility of the end by-products.